Two forms of artificial lift that help prolong the life of hydrocarbon wells are the use of gas lift and well unloading units. These two forms of artificial lift are common knowledge in the industry and are applied around the world. Moreover, each have inherent challenges, particularly in offshore environments where cost and space become important limitations.
As reservoir pressure declines due to depletion, the lift performance of oil wells suffers and at a certain point the well is no longer able to produce liquids to the surface naturally or economically because the pressure at the reservoir is not large enough to overcome the hydrostatic head of the fluids between it and the production tree at the platform. To increase the hydrocarbon production, the lift performance or inflow performance must be enhanced. If the inflow performance cannot be changed, which is typically the case, then the vertical lift performance must be improved to allow the well to flow. Two effective ways to do this are to reduce the wellhead flowing pressure at the surface or to reduce the hydrostatic head of fluid in the production tubing. Reducing the pressure at the surface can be achieved by using a Well Unloading Unit (WUU). This involves the use of pumping equipment on the surface to reduce backpressure of the well thus allowing flow up the well to surface. The fluids are subsequently pumped into the production pipeline at higher pressure. The problem associated with the conventional well unloading unit process is that any gas produced is vented to the atmosphere and lost. This is both an environmental concern and a lost production/revenue opportunity as the gas has value and could be sold.
Gas lift is another widely used and effective form of artificial lift applied in the industry. Gas lift involves the process of injecting gas at high pressure into the annulus of a well, typically an annulus between the production tubing and the innermost well casing. The gas enters the production tubing several thousand feet below the surface through a check valve and has the desired effect of reducing the fluid gradient in the tubing and thus lowering the wellbore flowing pressure. This increases the drawdown on the well and increases both liquid rates and reserves.
The major problem with applying gas lift to a well is that high pressure gas is required, typically greater than 1000 psi. This gas source can come from other high pressure gas wells being produced on the platform or by installing a compressor to take low pressure gas, compress it, and use it for gas lifting.
Oftentimes, using high pressure gas from other wells is not an option for operations. Additionally, even if there is a well with high pressure gas, it is only a short-term solution as reservoir pressures decline quickly and the gas pressure soon reaches a point where it is not adequate for gas lifting. The other option is to install a gas lift compressor. This is preferred as the pressure can be regulated and a stable supply of gas can be achieved. However, the problem with this option is the high cost, large footprint and immobility of compressors. A gas lift compressor typically requires an investment of more than US$ 2 million. Additionally, the units are immobile—the cost to move a gas lift compressor from one platform to another is more expensive than the compressor itself. A gas lift compressor also has a large foot print and takes up a big portion of the deck space on an offshore platform. If a platform does not warrant the installation of a gas lift compressor due to economics or spacial limitations, then hydrocarbons are typically left behind in the reservoir.